Fields of Disclosure
The disclosure relates generally to the field of fluid separation. More specifically, the disclosure relates to the cryogenic separation of contaminants, such as acid gas, from a hydrocarbon.
Description of Related Art
This section is intended to introduce various aspects of the art, which may be associated with the present disclosure. This discussion is intended to provide a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
The production of natural gas hydrocarbons, such as methane and ethane, from a reservoir oftentimes carries with it the incidental production of non-hydrocarbon gases. Such gases include contaminants, such as at least one of carbon dioxide (“CO2”), hydrogen sulfide (“H2S”), carbonyl sulfide, carbon disulfide and various mercaptans. When a feed stream being produced from a reservoir includes these contaminants mixed with hydrocarbons, the stream is oftentimes referred to as “sour gas.”
Many natural gas reservoirs have relatively low percentages of hydrocarbons and relatively high percentages of contaminants. Contaminants may act as a diluent and lower the heat content of hydrocarbons. Some contaminants, like sulfur-bearing compounds, are noxious and may even be lethal. Additionally, in the presence of water some contaminants can become quite corrosive.
It is desirable to remove contaminants from a stream containing hydrocarbons to produce sweet and concentrated hydrocarbons. Specifications for pipeline quality natural gas typically call for a maximum of 2-4% CO2 and ¼ grain H2S per 100 scf (4 ppmv) or 5 mg/Nm3 H2S. Specifications for lower temperature processes such as natural gas liquefaction plants or nitrogen rejection units typically require less than 50 ppm CO2.
The separation of contaminants from hydrocarbons is difficult and consequently significant work has been applied to the development of hydrocarbon/contaminant separation methods. These methods can be placed into three general classes: absorption by solvents (physical, chemical and hybrids), adsorption by solids, and distillation.
Separation by distillation of some mixtures can be relatively simple and, as such, is widely used in the natural gas industry. However, distillation of mixtures of natural gas hydrocarbons, primarily methane, and one of the most common contaminants in natural gas, carbon dioxide, can present significant difficulties. Conventional distillation principles and conventional distillation equipment are predicated on the presence of only vapor and liquid phases throughout the distillation tower. The separation of CO2 from methane by distillation involves temperature and pressure conditions that result in solidification of CO2 if a pipeline or better quality hydrocarbon product is desired. The required temperatures are cold temperatures typically referred to as cryogenic temperatures.
Certain cryogenic distillations can overcome the above mentioned difficulties. These cryogenic distillations provide the appropriate mechanism to handle the formation and subsequent melting of solids during the separation of solid-forming contaminants from hydrocarbons. The formation of solid contaminants in equilibrium with vapor-liquid mixtures of hydrocarbons and contaminants at particular conditions of temperature and pressure takes place in a controlled freeze zone section.
The solid contaminants formed in the controlled freeze zone section fall into a liquid of the controlled freeze zone section that is held above the melting point of the solid contaminants. The liquid is held at a sufficiently warm temperature to melt the solid contaminants. The liquid is part of a melt tray assembly of the controlled freeze zone section. To ensure that all of the solid contaminants melt in the liquid and none exit the controlled freeze zone section and/or plug a liquid discharge line, there needs to be sufficient warm liquid thermal mass in the controlled freeze zone section. In other words, the liquid in the melt tray assembly needs to at least be at a predetermined liquid level.
Liquid level indicators, such as differential pressure cells, guided wave radar sensors and a nucleonic mechanism have been used to help determine the liquid level, but these indicators have disadvantages. Differential pressure cells do not work well in determining the liquid level if the solid contaminants plug the differential pressure cells or associated pressure taps. Guided wave radar sensors do not work well because the temperature and pressure of the controlled freeze zone section is too close to the critical conditions of liquid and vapor, thereby making liquid and vapor nearly indistinguishable. Furthermore, compositional and pressure changes of the stream can cause changes in fluid density, making measurements inconsistent over time. The nucleonic mechanism does not work well in the presence of unsteady amounts of solids.
A need exists for improved technology that maintains at least a predetermined liquid level in a distillation tower so that a minimum warm liquid thermal mass is provided to reliably melt all solid contaminants in the liquid of the melt tray assembly and so that plugging of the controlled freeze zone section liquid discharge is avoided.